Co-production of power and hydrocarbons

ABSTRACT

A process ( 10 ) for co-producing power and hydrocarbons includes gasifying ( 16, 70 ) coal to produce a synthesis gas ( 36 ) and a combustion gas ( 86 ) both comprising at least CO 1 H 2  and CO 2  and being at elevated pressure, separating CO 2  ( 18, 48 ) from the synthesis gas, and synthesizing ( 20, 22 ) hydrocarbons from the synthesis gas. Power ( 114 ) is generated from the combustion gas, including by combusting ( 78 ) the combustion gas in the presence of oxygen and in the presence of at least a portion of the separated CO2 as moderating agent to produce a hot combusted gas ( 106 ) which includes CO 2 . The CO2 is recycled ( 112 ) or recovered from the combusted gas. In certain embodiments, the process ( 10 ) produces a CO 2  exhaust stream ( 134 ) for sequestration or capturing for further use.

THIS INVENTION relates to the co-production of power and hydrocarbons.In particular, the invention relates to a process for co-producing powerand hydrocarbons.

Integrated Gasification Combined Cycle (IGCC) processes haveenvironmental advantages over conventional coal-fired power plants.Synthesis gas produced by a gasifier of the IGCC process can also beused as a feedstock for co-production of liquid hydrocarbons and/orchemicals. In view of environmental pressures to reduce CO₂ emissions tothe atmosphere, a hydrocarbon synthesis process integrated with an IGCCprocess that provides the opportunity for capturing of CO₂ forsequestration would be desirable.

It is possible to capture CO₂ exhausted from a gas turbine unit of anIGCC process by removing the CO₂ from the exhaust or stack gases.However, such exhaust or stack gases are at a low pressure and theremoval of CO₂ would conventionally require separation of CO₂ and N₂that was introduced by combustion air fed to a combustor of the gasturbine unit. An alternative approach is to minimise the CO₂concentration in the exhaust or stack gases, e.g. by running the gasturbine on H₂. In this approach, CO₂ is removed from the combustion gas(mostly H₂) fed to the combustor, rendering the exhaust or stack gases amixture predominantly of N₂ and water. However, H₂ has a low heatingvalue compared to other potential combustion gases containing CO and/orCH₄.

It would be an advantage to provide an IGCC process integrated with ahydrocarbon production process which shows economic (i.e. capital andoperating cost) benefits and environmental benefits.

According to the invention, there is provided a process for co-producingpower and hydrocarbons, the process including

gasifying coal to produce a synthesis gas and a combustion gas bothcomprising at least CO, H₂ and CO₂ and being at elevated pressure;

separating CO₂ from the synthesis gas;

synthesizing hydrocarbons from the synthesis gas;

generating power from the combustion gas, including combusting thecombustion gas in the presence of oxygen and in the presence of at leasta portion of said separated CO₂ as moderating agent to produce acombusted gas which includes CO₂; and

recovering or recycling the CO₂ from the combusted gas or a gas derivedtherefrom.

As used in this specification, the term wet gasification stage means anentrained flow gasification stage in which water is used as a carrierfor solid feedstock (e.g. coal). It is thus a slurry that is fed to thegasification stage.

As used in this specification, the term dry gasification stage means anentrained flow gasification stage in which a gas is used as a carrierfor solid feedstock (e.g. coal).

The coal may be gasified in a wet gasification stage to produce thecombustion gas and in a dry gasification stage to produce the synthesisgas.

The combustion gas may be produced at a pressure of at least 45 bar,more preferably at least 55 bar, most preferably at least 65 bar, e.g.about 70 bar. Typically, the wet gasification stage uses a water quenchto cool the combustion gas.

The molar ratio of H₂ and CO in the combustion gas may be higher thanthe molar ratio of H₂ and CO in the synthesis gas. For avoidance ofdoubt, the phrase “the molar ratio of H₂ and CO” as used in thisspecification means the molar concentration of H₂ divided by the molarconcentration of CO. The molar ratio of H₂/CO has an identical meaning.

The molar ratio of H₂/CO in the combustion gas may be at least 0.6.

Preferably, the molar ratio is at least 0.8, more preferably at least0.9, e.g. about 0.96. Typically, the molar ratio of H₂/CO in thecombustion gas is between 0.6 and 1.0.

The dry gasification stage should produce synthesis gas at a pressurewhich is sufficiently high, taking into account pressure losses overprocess units to allow hydrocarbon synthesis at a suitably highpressure. Typically the synthesis gas precursor is at a pressure ofbetween about 40 bar and about 50 bar, e.g. about 45 bar. Typically, thedry gasification stage includes a gasification stage waste heat boiler.

The molar ratio of H₂/CO in the synthesis gas may be between about 0.3and about 0.6, preferably between about 0.3 and about 0.4, e.g. about0.4.

The process may include enriching a first portion of the combustion gaswith H₂ to produce an H₂-enriched gas. Enriching a first portion of thecombustion gas with H₂ may include subjecting said first portion of thecombustion gas to water gas shift conversion thereby to produce theH₂-enriched gas. Typically the water gas shift conversion is a sourshift, i.e. containing a catalyst suitable for reacting carbon monoxideand water to produce additional hydrogen in the presence of sulphur.

The process may include purifying a portion of the H₂-enriched gas, e.g.by using membranes and/or pressure swing adsorption, to produceessentially pure hydrogen. The essentially pure hydrogen may be used forhydro-processing of hydrocarbons synthesised from the synthesis gas.

The process may include mixing at least a portion of the H₂-enriched gaswith the synthesis gas, prior to synthesizing hydrocarbons from thesynthesis gas, to provide synthesis gas with a higher molar ratio ofH₂/CO.

The H₂-enriched gas may be at elevated pressure. Mixing at least aportion of the H₂-enriched gas with the synthesis gas may includepassing the H₂-enriched gas through an expansion turbine to generatepower.

Generating power from the combustion gas typically includes expandingthe combusted gas through a gas turbine expander to generate power andto produce hot exhaust gas, with the CO₂ then being recovered from thehot exhaust gas. Typically, the combustion of the combustion gas occursin a combustor. The hot exhaust gas may be at or above atmosphericpressure.

Generating power from the combustion gas may also include recoveringheat from the hot exhaust gas in a waste heat recovery stage. Typically,the waste heat recovery stage includes a waste heat recovery stage wasteheat boiler. Typically, recovering heat from the hot exhaust gas in thewaste heat recovery stage thus includes generating steam in the wasteheat recovery stage waste heat boiler. The generated steam may be usedto drive a steam turbine to produce power, or the steam may be usedelsewhere in the process for other purposes.

The waste heat recovery stage waste heat boiler may be a co-fired wasteheat boiler. The synthesising of hydrocarbons from the synthesis gas mayproduce a fuel gas. The waste heat recovery stage waste heat boiler maybe co-fired with the fuel gas to raise the pressure and/or thetemperature of the steam generated by the waste heat recovery stagewaste heat boiler.

The process may include separating air to produce oxygen. The oxygen maybe used to combust the combustion gas to produce the hot combusted gas.Typically, the oxygen must be produced at pressure to exceed theoperating pressure of a combustor in which the combustion gas iscombusted. Typically, liquid oxygen is pumped to the required pressureand the liquid oxygen is then heated to produce oxygen gas which is thenused to combust the combustion gas.

The oxygen, at lower pressure, may also be used to combust the fuel gasthereby to co-fire the waste heat recovery stage waste heat boiler.

The oxygen is typically also used in the wet gasification stage and inthe dry gasification stage to gasify coal. This oxygen is the highestpressure oxygen used and the required pressure is typically achieved bypumping liquid oxygen, which is then evaporated at pressure.

Synthesising hydrocarbons from the synthesis gas may be effected in anyconventional fashion. Typically, the synthesising of hydrocarbons fromthe synthesis gas includes Fischer-Tropsch synthesis using one or moreFischer-Tropsch hydrocarbon synthesis stages, producing one or morehydrocarbon product streams and a Fischer-Tropsch tail gas whichincludes CO₂, CO and H₂.

The one or more Fischer-Tropsch hydrocarbon synthesis stages may beprovided with any suitable reactors such as one or more fixed bedreactors, slurry bed reactors, ebullating bed reactors or dry powderfluidised bed reactors. The pressure in the reactors may be between 1bar and 100 bar, typically below 45 bar, while the temperature may bebetween 160° C. and 380° C.

One or more of the Fischer-Tropsch hydrocarbon synthesis stages may be alow temperature Fischer-Tropsch hydrocarbon synthesis stage operating ata temperature of less than 280° C. Typically, in such a low temperatureFischer-Tropsch hydrocarbon synthesis stage, the hydrocarbon synthesisstage operates at a temperature of between 160° C. and 280° C.,preferably between 220° C. and 260° C., e.g. about 250° C. Such a lowtemperature Fischer-Tropsch hydrocarbon synthesis stage is thus a highchain growth, typically slurry bed, reaction stage, operating at apredetermined operating pressure in the range of 10 to 50 bar, typicallybelow 45 bar.

One or more of the Fischer-Tropsch hydrocarbon synthesis stages may be ahigh temperature Fischer-Tropsch hydrocarbon synthesis stage operatingat a temperature of at least 320° C. Typically, such a high temperatureFischer-Tropsch hydrocarbon synthesis stage operates at a temperature ofbetween 320° C. and 380° C., e.g. about 350° C., and at an operatingpressure in the range of 10 to 50 bar, typically below 45 bar. Such ahigh temperature Fischer-Tropsch hydrocarbon synthesis stage is a lowchain growth reaction stage, which typically employs a two-phasefluidised bed reactor. In contrast to the low temperatureFischer-Tropsch hydrocarbon synthesis stage, which may be characterisedby its ability to maintain a continuous liquid product phase in a slurrybed reactor, the high temperature Fischer-Tropsch hydrocarbon synthesisstage cannot produce a continuous liquid product phase in a fluidisedbed reactor.

The Fischer-Tropsch tail gas may be treated to remove CO₂. The CO₂ maybe removed in any conventional fashion, e.g. by using a Benfieldsolution. Typically, the Fischer-Tropsch tail gas is subjected to awater gas shift stage to convert CO to CO₂ and to produce more H₂. Thewater gas shift stage would typically be a conventional water gas shiftstage, i.e. a sweet shift stage.

The process may include separating H₂ from the Fischer-Tropsch tail gas(e.g. using pressure swing adsorption) and recycling the H₂ to the oneor more Fischer-Tropsch hydrocarbon synthesis stages.

Separating CO₂ from the synthesis gas may include treating the synthesisgas to remove sulphur and said CO₂. Treating the synthesis gas may beeffected in any conventional fashion, e.g. using a Rectisol processwhich includes a chilled methanol wash.

The process may include compressing at least a portion of the separatedCO₂ to exceed the operating pressure of a combustor used to generatepower from the combustion gas. The compressed CO₂ may be mixed withoxygen already at pressure, before feeding the CO₂ and oxygen to thecombustor.

Recovering or recycling the CO₂ from the combusted gas may includetreating exhaust gas from the waste heat recovery stage waste heatboiler, comprising predominantly CO₂ and water, to remove the water,leaving a CO₂ exhaust stream, which may be sequestrated in anyconventional fashion, or captured for further use. The CO₂ exhauststream may be combined with further CO₂ obtained from the treatment ofsynthesis gas and/or from the treatment of the Fischer-Tropsch tail gas.The process may include recycling some of the exhaust gas from the wasteheat recovery stage waste heat boiler, or some of the CO₂ exhauststream, to the combustor.

The process may include superheating steam from the waste heat recoverystage waste heat boiler using the fuel gas and air. In this event, astack gas produced by the superheating of the steam should not be mixedwith exhaust gas from the waste heat recovery stage waste heat boiler orwith the hot exhaust gas from the gas turbine expander.

The process may include using, instead of air, essentially pure oxygenor a combination of essentially pure oxygen and CO₂ in at least somefired equipment involved in the production of hydrocarbons. Stack gasesfrom such fired equipment may then be combined to consolidateCO₂-producing streams.

The invention will now be described, by way of example, with referenceto the accompanying diagrammatic drawings in which

FIG. 1 shows a process in accordance with the invention for aco-producing power and hydrocarbons; and

FIG. 2 shows in more detail a portion of the process of FIG. 1.

Referring to FIG. 1 of the drawings, reference numeral 10 generallyindicates a process in accordance with the invention for co-producingpower and hydrocarbons. The process 10 includes a coal-to-liquid (CTL)hydrocarbon synthesis facility generally indicated by reference numeral12 and an Integrated Gasification Combined Cycle (IGCC) facilitygenerally indicated by reference numeral 14.

The CTL facility 12 includes a dry gasification stage 16, a gas clean-upstage 18, a first Fischer-Tropsch hydrocarbon synthesis stage 20, asecond Fischer-Tropsch hydrocarbon synthesis stage 22 in series with thefirst Fischer-Tropsch hydrocarbon synthesis stage 20, a heavy endrecovery stage 24, a water gas or sweet shift stage 26, a CO₂ removalstage 28, a hydrogen separation stage 30, a reaction water treatmentstage 32 and a product work-up stage 34.

A syngas line 36 leads from the dry gasification stage 16 to the gasclean-up stage 18 and from the gas clean-up stage 18 through the firstand second Fischer-Tropsch hydrocarbon synthesis stages 20, 22. AFischer-Tropsch tail gas line 38 leads from the second Fischer-Tropschhydrocarbon synthesis stage 22 to the heavy end recovery stage 24 andfrom there to the water gas or sweet shift stage 26, the CO₂ removalstage 28 and eventually to the hydrogen separation stage 30. A hydrogenrecycle line 40 leads from the hydrogen separation stage 30 back to thefirst Fischer-Tropsch hydrocarbon synthesis stage 20 and a fuel gas line42 leads from the hydrogen separation stage 30 to the IGCC facility 14.

A syngas bypass line 44 bypasses the first Fischer-Tropsch hydrocarbonsynthesis stage 20.

A sulphur recovery line 46 and a CO₂ line 48 leave the gas clean-upstage 18.

Hydrocarbon product lines 50 and reaction water lines 52 leave the firstand second Fischer-Tropsch hydrocarbon synthesis stages 20, 22, with thereaction water lines 52 leading to the reaction water treatment stage 32and the hydrocarbon product lines 50 leading to the product work-upstage 34. The product work-up stage 34 is also connected to the heavyend recovery stage 24 by means of a light hydrocarbons line 54 leadingfrom the heavy end recovery stage 24 to the product work-up stage 34.

An oxygenates line 56 and water lines 58 leave the reaction watertreatment stage 32, whereas an LPG line 60, a naphta line 62 and adiesel line 64 leave the product work-up stage 34.

The CO₂ removal stage 28 is provided with a CO₂ line 66.

The IGCC facility 14 includes a wet gasification stage 70, a sour shiftstage 72, a hydrogen-enriched gas expansion stage 74, a gas clean-upstage 76, a combustion gas expansion stage 77, a gas combustion andexpansion stage 78 and a waste heat recovery stage 80 comprising aco-fired waste heat boiler 82 and steam turbines 84.

A combustion gas line 86 leads from the wet gasification stage 70 to thegas clean-up stage 76 and from the gas clean-up stage 76 to thecombustion gas expansion stage 77 and from there to the gas combustionand expansion stage 78. The combustion gas line 86 between the wetgasification stage 70 and the gas clean-up stage 76 also branches off tothe sour shift stage 72. An H₂-enriched gas line 88 leads from the sourshift stage 72 through the hydrogen-enriched gas expansion stage 74 andjoins the syngas line 36 between the dry gasification stage 16 and thegas clean-up stage 18 of the CTL facility 12.

A sulphur removal line 90 leaves the gas clean-up stage 76.

With reference to FIG. 2 of the drawings, the gas combustion andexpansion stage 78 includes a compressor 92 and a gas turbine expander94 drivingly connected to the compressor 92. The combustion gas line 86from the combustion gas expansion stage 77 leads to a combustor 96. ACO₂ line 98 leads into the compressor 92. A compressed CO₂ line 102leads from the compressor 92 to the combustor 96 and is joined by anoxygen line 100. A hot combusted gas line 104 leads from the combustor96 to the gas turbine expander 94. A hot exhaust gas line 106 leads fromthe gas turbine expander 94 to the co-fired waste heat boiler 82 of thewaste heat recovery stage 80.

A steam line 108 leads from the co-fired waste heat boiler 82 to thesteam turbines 84 and a condensate recycle line 110 leads back from thesteam turbines 84 to the co-fired waste heat boiler 82. The co-firedwaste heat boiler 82 is joined by the fuel gas line 42 from the CTLfacility 12 and is also provided with an exhaust gas line 112.

The hydrogen-enriched gas expansion stage 74, the combustion gasexpansion stage 77, the gas combustion and expansion stage 78 and thesteam turbines 84 provide electric power generally indicated byreference numeral 114. Electricity can be exported and used internally,e.g. in the CTL facility 12.

The CTL facility 12 and the IGCC facility 14 share an air separationunit 120, a CO₂ and water separation stage 122, a CO₂ compression andwater knock-out stage 124 and a water treatment stage 126.

The oxygen line 100 from the air separation unit 120 leads to the gascombustion and expansion stage 78, as hereinbefore indicated, but alsoto other oxygen users in both the CTL facility 12 and the IGCC facility14.

The CO₂ line 48 from the gas clean-up stage 18 of the CTL facility 12leads to the CO₂ and water separation stage 122 and the CO₂ line 98leads from the CO₂ and water separation stage 122 to the compressor 92of the gas combustion and expansion stage 78. A water line 128 leadsfrom the CO₂ and water separation stage 122 to the water treatment stage126.

The CO₂ compression and water knock-out stage 124 is joined by theexhaust gas line 112 from the waste heat recovery stage 80 and the CO₂line 66 from the CO₂ removal stage 28 of the CTL facility 12.

A water line 130 leads from the CO₂ compression and water knock-outstage 124 to the water treatment stage 126, which is also joined by thewater line 58 from the reaction water treatment stage 32 of the CTLfacility 12. One or more treated water lines 132, only one of which isshown for simplicity, leads from the water treatment stage 126 to boththe CTL facility 12 and the IGCC facility 14.

Referring again to FIG. 2 of the drawings, the air separation unit 120is provided with an air feed line 134 and a nitrogen production line136.

Particulate coal is gasified in the dry gasification stage 16 to producesynthesis gas. The dry gasification stage 16 may employ any conventionalentrained flow dry feed gasification technology, e.g. the Shell (tradename) dry gasification technology which produces a synthesis gas withlow inert and CO₂ content and an H₂/CO molar ratio of about 0.4.Although not shown in the drawings, a waste heat boiler is used to coolthe synthesis gas, which is typically produced at a pressure of about 45bar. The waste heat boiler produces process steam (not shown). Thesynthesis gas is fed by means of the syngas line 36 to the gas clean-upstage 18. The synthesis gas is however first enriched in hydrogen by theH₂-enriched gas flowing along the H₂-enriched gas line 88, thereby toincrease the H₂/CO molar ratio so that the H₂/CO molar ratio is in therange of between about 0.7 and about 2.5.

In the gas clean-up stage 18 the synthesis gas is cleaned inconventional fashion to remove sulphur, particulate material and CO₂.Conventional synthesis gas cleaning technology may be used, e.g. aRectisol process, amine washes and a CO₂ absorption process employing aBenfield solution. Sulphur is removed from the gas clean-up stage 18 bymeans of the sulphur recovery line 46 and the CO₂ is removed by means ofthe CO₂ line 48.

The clean synthesis gas is fed into the first Fischer-Tropschhydrocarbon synthesis stage 20 and from there into the secondFischer-Tropsch hydrocarbon synthesis stage 22 to convert the synthesisgas to hydrocarbons. Any conventional Fischer-Tropsch hydrocarbonsynthesis configuration may be used. In the embodiment shown in FIG. 1of the drawings, a two-stage process employing a synthesis gas bypass(using the syngas bypass line 44) and a hydrogen recycle (using thehydrogen recycle line 40) is illustrated. The Fischer-Tropschhydrocarbon synthesis stages 20, 22 may thus include one or moresuitable reactors such as a fluidised bed reactor, a tubular fixed bedreactor, a slurry bed reactor or an ebullating bed reactor. It may eveninclude multiple reactors operating under different conditions. Thepressure in the reactors may be between 1 bar and 100 bar but in thisembodiment a pressure of about 45 bar is used. The temperature may bebetween 160° C. and 380° C. Reactors will thus contain a Fischer-Tropschcatalyst, which will be in particulate form. The catalyst may contain,as its active catalyst component, Co, Fe, Ni, Ru, Re and/or Rh, butpreferable has Fe as its active catalyst component. The catalyst may beprovided with one or more promoters selected from an alkaline metal, V,Cr, Pt, Pd, La, Re, Rh, Ru, Th, Mn, Cu, Mg, K, Na, Ca, Ba, Zn and Zr.The catalyst may be a supported catalyst, in which case the activecatalyst component, e.g. Co, is supported on a suitable support such asAl₂O₃, TiO₂, SiO₂, ZnO or a combination of these. Preferably, thecatalyst is an unsupported Fe catalyst.

In the first Fischer-Tropsch hydrocarbon synthesis stage 20 and thesecond Fischer-Tropsch hydrocarbon synthesis stage 22, reaction water isproduced which is removed by means of the reaction water lines 52 andfed to the reaction water treatment stage 32. In the reaction watertreatment stage 32 oxygenates are separated from the reaction waterusing conventional separation technology and removed by means of theoxygenates line 56. Water is withdrawn from the reaction water treatmentstage 32 and fed to the water treatment stage 126 by means of the waterline 58.

Hydrocarbon products produced in the first Fischer-Tropsch hydrocarbonsynthesis stage 20 and the second Fischer-Tropsch hydrocarbon synthesisstage 22 are removed by means of the hydrocarbon product lines 50 andfed to the product work-up stage 34. In the product work-up stage 34,the hydrocarbon products are worked up to produce LPG gas, naphta anddiesel, respectively removed from the product work-up stage 34 by meansof the LPG line 60, the naphta line 62 and the diesel line 64.

A Fischer-Tropsch tail gas is removed from the second Fischer-Tropschhydrocarbon synthesis stage 22 by means of the Fischer-Tropsch tail gasline 38 and fed to the heavy end recovery stage 24 where lighthydrocarbons, e.g. C₃ ⁺ hydrocarbons are removed in conventional fashionand fed by means of the light hydrocarbons line 54 to the productwork-up stage 34 to be worked up with the hydrocarbon products enteringthe product work-up stage 34 by means of the hydrocarbon product lines50. The Fischer-Tropsch tail gas is then mixed with steam (not shown)and subjected to the well-known water gas shift reaction to convert COand water (steam) to CO₂ and H₂, in the sweet shift stage 26. From thesweet shift stage 26, the Fischer-Tropsch tail gas, now with anincreased concentration of CO₂ and H₂, is then fed to the CO₂ removalstage 28. In the CO₂ removal stage 28, conventional technology is againused to remove CO₂ and water from the Fischer-Tropsch tail gas.Typically, this includes the use of a Benfield solution to absorb theCO₂. The CO₂ is then again desorbed and the CO₂ and water are removedfrom the CO₂ removal stage 28 by means of the CO₂ line 66 and fed to theCO₂ compression and water knock-out stage 124.

The Fischer-Tropsch tail gas from the CO₂ removal stage 28, now with areduced concentration of CO₂ and water, is fed to the hydrogenseparation stage 30. In the hydrogen separation stage 30, conventionalpressure swing adsorption is used to separate hydrogen from theFischer-Tropsch tail gas, producing a fuel gas comprising mostly CO andhydrocarbon gasses. The hydrogen is recycled by means of the hydrogenrecycle line 40 to the first Fischer-Tropsch hydrocarbon synthesis stage20. The fuel gas is removed by means of the fuel gas line 42 and fed tothe waste heat recovery stage 80 of the IGCC facility 14. Optionally,the fuel gas may be sold as synthetic natural gas and may also beblended with other gas streams to obtain the correct specification forsale.

For purposes of generating power, a coal slurry is gasified in the wetgasification stage 70 of the IGCC facility 14 to produce combustion gas.Any conventional wet gasification technology may be used, such as theGeneral Electric (trade name) slurry fed gasification technology. Wateris used as a coal carrier so that a coal slurry is gasified resulting inan H₂/CO molar ratio of about 0.96 in the combustion gas produced in thewet gasification stage 70. The combustion gas is typically cooled usinga water quench. The combustion gas is produced at a pressure of morethan 70 bar.

The combustion gas from the wet gasification stage 70 is removed bymeans of the combustion gas line 86 and fed to the gas clean-up stage76. Before the gas clean-up stage 76, a portion of the combustion gas ismixed with steam as required (not shown) and diverted to the sour shiftstage 72 where CO and water are converted to CO₂ and H₂, using thewell-known water gas shift reaction. An H₂-enriched gas is thus producedin the sour shift stage 72 and the H₂-enriched gas is fed by means ofthe H₂-enriched gas line 88 to the hydrogen expansion stage 74. In thehydrogen expansion stage 74, the H₂-enriched gas is expanded through anexpansion turbine which drives a generator thereby to produce electricalpower. In the expansion turbine, the pressure of the H₂-enriched gas isdropped from more than 70 bar to about 45 bar, whereafter theH₂-enriched gas is mixed with the synthesis gas in the syngas line 36 toincrease the H₂/CO molar ratio of the synthesis gas as hereinbeforedescribed.

In the gas clean-up stage 76, the combustion gas is cleaned inconventional fashion to remove sulphur along the sulphur removal line90. The clean combustion gas is then fed to the gas combustion andexpansion stage 78 by means of the combustion gas line 86 via thecombustion gas expansion stage 77. In the combustion gas expansion stage77, the clean combustion gas is expanded through a gas turbine expander,reducing the pressure of the combustion gas to the operating pressure ofthe gas combustion and expansion stage 78, and generating electricity(generally indicated by reference numeral 114).

Air is separated in the air separation unit 120 using conventionalcryogenic air separation technology to produce nitrogen and oxygen, asshown in more detail in FIG. 2. The nitrogen is removed by means of thenitrogen line 136 and employed in the CTL facility 12 and the IGCCfacility 14 where required, or recovered for commercial purposes orpurged. The oxygen from the air separation unit 120 is removed by theoxygen line 100 and also distributed to the CTL facility 12 and the IGCCfacility 14 for use where required. A portion of the oxygen is fed bymeans of the oxygen line 100 to the combustor 96 of the gas combustionand expansion stage 78 (see FIG. 2).

In the CO₂ and water separation stage 122, water is knocked from theCO₂. The water is fed by means of the water line 128 to the watertreatment stage 126. The CO₂ is removed from the CO₂ and waterseparation stage 122 and fed to the compressor 92 of the gas combustionand expansion stage 78.

CO₂ in the CO₂ line 98 is thus fed to the compressor 92 and compressed.The compressed CO₂ is mixed with high pressure oxygen from the oxygenline 100 and the compressed CO₂ and oxygen mixture is fed by means ofthe compressed CO₂ and oxygen line 102 to the combustor 96. Combustiongas fed by means of the combustion gas line 86 is combusted in thecombustor 96, in the presence of the CO₂ and oxygen to produce a hotcombusted gas. The hot combusted gas is removed by means of the hotcombusted gas line 104 and passed through the gas turbine expander 94which inter alia drives the compressor 92 by means of a directmechanical coupling. The gas turbine expander 94 is also used to drivegenerators (not shown) to generate electric power generally indicated byreference numeral 114. A hot exhaust gas, comprising mostly CO₂ andwater, is removed from the gas turbine expander 94 by means of the hotexhaust gas line 106 and fed to the co-fired waste heat boiler 82 of thewaste heat recovery stage 80. The waste heat boiler 82 is fired withfuel gas fed by means of the fuel gas line 42 and produces high pressuresteam which is fed by means of the steam line 108 to the steam turbines84 which are used to drive generators (not shown) to generate electricpower generally indicated by reference numeral 114. Condensate isrecycled from the steam turbines 84 to the co-fired waste heat boiler82.

The gas turbine expander 94 and/or the steam turbines 84 may beintegrated with the air separation unit 120 to drive air compressors ofthe air separation unit 120 by means of direct mechanical coupling.

In the co-fired waste heat boiler 82, the exhaust gas produced by thecombustion of the fuel gas is combined with the exhaust gas from the gasturbine expander 94 and removed by means of the exhaust gas line 112. Aswill be appreciated, this exhaust gas comprises mostly CO₂ and water.The exhaust gas is fed to the CO₂ compression and water knock-out stage124 where it is compressed. Water is knocked out from the compressed CO₂and fed by means of the water line 130 to the water treatment stage 126.The compressed CO₂ from the CO₂ compression and water knock-out stage124 is available for sequestration or capture, as indicated by referencenumeral 134. The compressed CO₂ may thus for example be employed forenhanced oil recovery (EOR) or enhanced coal-bed methane recovery(ECBMR).

In the water treatment stage 126, water fed to the water treatment stage126 along the water lines 58, 128 and 130 are treated to produce waterof requisite levels. The treated water is removed by means of thetreated water lines 132 and distributed to both the CTL facility 12 andthe IGCC facility 14, inter alia to be used as boiler feed water.

Selecting a gasification technology best suited to a particular ventureinvolves consideration of various factors, including feedstockcharacteristics, capital cost, operating cost, reliability, intendedapplication of the produced synthesis gas, etc. The invention, asillustrated, provides an integrated IGCC power plant and CTL plant whichbenefit from optimal economies of scale of the capital intensive partsand also provide for CO₂ capturing or sequestration. A combination ofdry gasification and wet gasification is used to provide intermediatestreams suited to hydrocarbon synthesis and power productionrespectively. Advantageously for power production, a wet gasificationprocess can supply combustion gas at pressures higher than 70 bar. A drygasification process can supply synthesis gas precursor at pressuresmatching the requirement for Fischer-Tropsch hydrocarbon synthesis,typically around 45 bar. The combustion gas typically has a higherhydrogen content than the synthesis gas precursor, a portion of thecombustion gas thus providing a suitable feed material for enrichmentwith hydrogen to upwardly adjust the molar ratio of H₂ and CO of thesynthesis gas precursor. Furthermore, the wet gasification stagetypically employs a water quench and the combustion gas is thussaturated with water at relatively high temperature. Advantageously, thesteam requirement of the sour shift used to enrich the first portion ofthe combustion gas with hydrogen is thus reduced. In addition, the drygasification stage typically employs a waste heat boiler providingprocess steam. Overall energy efficiency is thus enhanced by thecombination of dry- and wet gasification technologies, because the drygasification approach is more efficient at producing a synthesis gasrich in carbon monoxide and the required process steam, while the wetgasification process is the most efficient approach to produce anenriched hydrogen gas.

Advantageously, the IGCC facility may be appropriately sized forinternal consumption of energy only or, instead, if there is a suitablemarket for electricity in the vicinity, the IGCC facility may be sizedto maximise economy of scale for the export of power.

Air separation units are expensive to construct and energy-intensive tooperate due to large compression requirements. Advantageously, when anIGCC facility and a CTL facility share an air separation unit, economyof scale lowers the cost per unit volume of oxygen required by the CTLfacility. Power-producing turbines of the IGCC facility may beintegrated by direct mechanical coupling to air compressors of the airseparation unit, resulting in improved plant energy efficiency, since aloss in efficiency associated with electrical power generation isavoided.

Sharing of utilities lowers the cost of expensive ultra-pure water usedas boiler feed water make-up to produce steam for use in the steamturbines in the IGCC facility. Savings can also be realised in utilitycosts for the CTL plant because of better economies of scale.

Fuel gas produced by the CTL facility, which in many cases would bepurged, can be used as fuel in the IGCC facility, e.g. in heat recoveryunits of the IGCC facility. This allows the production of steam at ahigher pressure and/or a higher temperature. As the fuel gas will comeas internal transfer from a large scale facility, costs will be reduced.From the perspective of the CTL facility, this option provides aninternal and assured consumer for the fuel gas stream.

Power for internal consumption on the CTL facility is generated atoptimal cost and efficiency, improving the overall carbon and plantefficiency of the integrated CTL and IGCC facilities compared to that oftwo stand-alone facilities.

Finally, the integration of a CTL facility and an IGCC facility allowscapturing of CO₂ from the off-gas of the IGCC facility. This is achievedby directing a portion of the CO₂ produced in the CTL facility, to thecompressor of the gas turbine expander of the IGCC facility, togetherwith pure oxygen from an air separation unit, thereby avoiding theintroduction of nitrogen into the combustor of the IGCC facility. Thisallows the gas turbine to be run using a mixture of oxygen and CO₂ astemperature moderating agent instead of a conventional mixture of oxygenand N₂ when air is used. The final off-gas from the IGCC facility willthus be a relatively pure combination of CO₂ and water vapour, which canbe combined with the remaining CO₂ produced by the CTL facility forexport, allowing the CO₂ processing and compression facilities tobenefit from an increased economy of scale.

1. A process for co-producing power and hydrocarbons, the process including gasifying coal to produce a synthesis gas and a combustion gas both comprising at least CO, H₂ and CO₂ and being at elevated pressure; separating CO₂ from the synthesis gas; synthesizing hydrocarbons from the synthesis gas; generating power from the combustion gas, including combusting the combustion gas in the presence of oxygen and in the presence of at least a portion of said separated CO₂ as moderating agent to produce a combusted gas which includes CO₂; and recovering or recycling the CO₂ from the combusted gas or a gas derived therefrom.
 2. The process as claimed in claim 1, in which coal is gasified in a wet gasification stage to produce the combustion gas and in a dry gasification stage to produce the synthesis gas.
 3. The process as claimed in claim 1, in which the molar ratio of H₂ and CO in the combustion gas is higher than the molar ratio of H₂ and CO in the synthesis gas.
 4. The process as claimed in claim 1, in which the molar ratio of H₂/CO in the combustion gas is at least 0.6.
 5. The process as claimed in claim 1, in which the molar ratio of H₂/CO in the synthesis gas is between about 0.3 and about 0.6.
 6. The process as claimed in claim 1, which includes enriching a first portion of the combustion gas with H₂ to produce an H₂-enriched gas.
 7. The process as claimed in claim 6, which includes purifying a portion of the H₂-enriched gas to produce essentially pure hydrogen.
 8. The process as claimed in claim 6, which includes mixing at least a portion of the H₂-enriched gas with the synthesis gas, prior to synthesizing hydrocarbons from the synthesis gas, to provide synthesis gas with a higher molar ratio of H₂/CO.
 9. The process as claimed in claim 8, in which the H₂-enriched gas is at elevated pressure and in which mixing at least a portion of the H₂-enriched gas with the synthesis gas includes passing the H₂-enriched gas through an expansion turbine to generate power.
 10. The process as claimed in claim 1, in which generating power from the combustion gas includes expanding the combusted gas through a gas turbine expander to generate power and to produce hot exhaust gas, and recovering heat from the hot exhaust gas in a waste heat recovery stage which includes a waste heat boiler generating steam.
 11. The process as claimed in claim 10, in which the waste heat boiler is a co-fired waste heat boiler and in which the synthesising of hydrocarbons from the synthesis gas produces a fuel gas, the waste heat boiler being co-fired with the fuel gas to raise the pressure and/or the temperature of the steam generated by the waste heat boiler.
 12. The process as claimed in claim 1, in which the synthesising of hydrocarbons from the synthesis gas includes Fischer-Tropsch synthesis using one or more Fischer-Tropsch hydrocarbon synthesis stages, producing one or more hydrocarbon product streams and a Fischer-Tropsch tail gas which includes CO₂, CO and H₂.
 13. The process as claimed in claim 1, which includes compressing at least a portion of the separated CO₂ to exceed the operating pressure of a combustor used to generate power from the combustion gas, and mixing the compressed CO₂ with oxygen already at pressure, before feeding the CO₂ and oxygen to the combustor.
 14. The process as claimed in claim 10, in which recovering or recycling the CO₂ from the combusted gas includes treating exhaust gas from the waste heat boiler, comprising predominantly CO₂ and water, to remove the water, leaving a CO₂ exhaust stream, which is sequestrated or captured for further use. 